Production string activated wellbore sealing apparatus and method for sealing a wellbore using a production string

ABSTRACT

A wellbore sealing apparatus positioned along production string tubing is provided to allow for sealing of a wellbore without needing to use a work string. The sealing apparatus includes an outer sleeve, an inner mandrel telescopically received within the outer sleeve, a sealing element positioned on the inner mandrel, an actuator interaction assembly and top and bottom seal pushers. An actuator positioned along the production rod string is also provided. The wellbore sealing apparatus has a sealed or engaged position and a disengaged position. To seal the wellbore, the actuator is pulled upwardly via the production rod string and couples to the actuator interaction assembly of the sealing apparatus. The continued upward movement of the actuator results in the inner mandrel moving further into the outer sleeve and the top and bottom pushers exerting opposing forces on the sealing element. The sealing element compresses and expands to seal the wellbore.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority of U.S. Provisional Patent Application Ser. No. 61/719,765, entitled “Production String Activated Wellbore Sealing Apparatus and Method for Sealing a Wellbore Using a Production String”, filed Oct. 29, 2012, and hereby incorporates the same provisional application by reference herein in its entirety.

TECHNICAL FIELD

The present disclosure is related to the field of wellbore sealing apparatuses, in particular, wellbore sealing apparatuses that can be connected in-line with a production string.

BACKGROUND

Various wellbore sealing apparatuses are used in producing oil wells to provide a seal between the outside of tubing inserted into the wellbore and the inside of the casing, liner or wall of the wellbore. Providing a seal between the outside of the tubing and the inside of the wellbore is necessary in order to isolate different zones within the wellbore to facilitate various tasks. The wellbore sealing apparatuses used for this purpose are commonly known as packers. Production packers remain in wells while they are producing oil while service packers are used with work strings and are temporarily in wells for various well maintenance tasks, including cement squeezing, acidizing, fracturing and well testing.

Many packers are not removable once they are put in place. A packer of this kind must be milled out of the wellbore when the user no longer wishes to use them. This is a time-consuming and expensive process, and the packer is destroyed as a result.

More complex packers that use mechanical and hydraulic systems to engage and disengage can be removed more easily and reused. However, these packers cannot be operated using a production string. Instead, they require the use of additional equipment, specifically service rigs hooked up to a work string. To get the work string into the wellbore the production string must first be removed. When the work is completed, the work string is removed and the production string placed back in the well. This complicated process is time consuming and costly.

Work strings can be used to deposit fluids into a wellbore when performing various maintenance tasks. Sand and other debris can collect at the sites of the perforations in a formation during production, which slows the rate of oil production and can cause wear on the production pumps. When the rate of production slows to a particular level, the well is cleaned. Typically this type of maintenance is performed using a work string which allows fluid to be pushed into the wellbore to clean the sand and other debris away from the perforations. Along with being forced into the formation through the perforation, thereby pushing the sand and debris from the openings, the fluid fills the space between the casing and the work string tubing. The amount of fluid required is typically greater than can be transported in standard tank trucks, therefore more than one trip has to be made. The majority of the fluid must be removed before the work string is removed and the production string put back in place. Whether or not sufficient sand and debris has been removed during the maintenance process can only be determined after the production string is replaced in the wellbore. Therefore, only one cleaning cycle can occur every day.

It is therefore desirable to provide a wellbore sealing apparatus that overcomes the shortcomings of the prior art.

SUMMARY

A wellbore sealing apparatus which is positioned along production string tubing is provided. This sealing apparatus combines an outer sleeve, an inner mandrel telescopically received within the outer sleeve, a sealing element that expands when compressed, an actuator interaction assembly and top and bottom seal pushers. The sealing element is disposed on the inner mandrel with the top seal pusher uphole and the bottom seal pusher downhole. The actuator interaction assembly has a means to couple to an actuator and is positioned downhole, but in-line with the inner mandrel. The inner mandrel includes a pin or peg extending outwardly and interacts with a slot in the outer sleeve to limit rotation of the inner mandrel. When the actuator couples to the actuator interaction assembly, the inner mandrel is pushed upwardly to be telescopically received into the outer sleeve. This movement also causes the top and bottom seal pushers to be brought closer together and exert opposing pressure on the sealing element such that the sealing element compresses and expands to form a seal with the wellbore casing.

In one aspect of the invention, the actuator interaction assembly contains one or more slots in the assembly body that allow an actuator having one or more connectors to couple to the actuator interaction assembly by sliding the one or more connectors into the one or more slots. Alternatively the slots may be on the actuator and the connectors may be on the assembly body. In one aspect of the invention the slots are J-shaped.

In a further aspect of the invention, the actuator interaction assembly may also include at least one gap between the first and section sections of the assembly body to allow connectors in the actuator to pass through the actuation interaction assembly. Alternatively, there may be at least one by-pass gap extending longitudinally along the length of the actuator to allow it to pass by connectors in the actuator interaction assembly.

The actuator interaction assembly can further comprise a top assembly sleeve, an assembly body having first and second sections, and a bottom assembly sleeve. The top and bottom assembly sleeves can comprise an assembly body enclosure for housing the first and second sections of the assembly body. The first and second sections of the assembly body can also each include a slot and/or a connector. The first and second sections of the assembly body can be oriented such that slots or connectors, or a combination thereof, can connect or couple to the actuator.

In one aspect of the invention the length and location of the peg slot on the outer sleeve and the location of the at least one peg on the inner mandrel can be such that the inner mandrel is unable to extend out of the outer sleeve to a position where substances in the well could enter the central conduit running through the inside of the wellbore sealing apparatus through the at least one peg slot.

In some embodiments, the wellbore sealing apparatus can further comprise a seal piston. The seal piston can attach to the top of the inner mandrel and the seal piston and the inner mandrel can be inserted into the bottom of the outer sleeve. The inner mandrel can slide back and forth within the outer sleeve while the seal piston acts to prevent substances from leaking into a central conduit running through the inside of the wellbore sealing apparatus by forming a seal between the inside of the outer sleeve and the outside of the seal piston. In some embodiments, the seal between the inside of the outer sleeve and the outside of the seal piston can be airtight.

The seal piston can further comprise a piston body, a seal and a cap. The piston body can comprise a threaded cap insert, a seal holder and a first collar. The cap can comprise a threaded midsection. The seal can be put over the piston body around the seal holder and the threaded midsection of the cap can be threaded onto the threaded cap insert of the piston body to secure the seal in place.

In another aspect of the invention the sealing apparatus also includes a biasing means, disposed on the inner mandrel between the outer sleeve and the top seal pusher. The biasing means can assist in disengaging the wellbore sealing apparatus by pushing the inner mandrel out of the outer sleeve when the actuator stops pushing the inner mandrel into the outer sleeve.

The wellbore sealing apparatus can further comprise a spring pusher connected to the bottom end of the outer sleeve. The main body of the spring pusher can comprise a spring slot, with the spring slot oriented such the top end of the spring fits into the spring slot.

An actuator positioned on a production rod string is also provided. The actuator has a coupling or connecting means that allows it to couple to an actuator interaction assembly when the production rod string is pulled upwardly. The coupling or connecting means can be connectors or slots, or a combination thereof. The actuator may also comprise a by-pass gap that allows it to pass by the connectors positioned on the actuator interaction assembly.

A method for sealing a wellbore using a production string is also provided. A sealing apparatus having a sealing element and an actuator interaction assembly is positioned along the production string tubing and an actuator positioned along the production rod string. The actuator is coupled or connected to the actuator interaction assembly of the sealing apparatus, and then the sealing element is compressed and expands to form a seal between the sealing apparatus and the wellbore casing.

The actuator interaction assembly may include slots and/or connectors which interact with corresponding connectors and/or slots on the actuator. This interaction allows the actuator to couple or connect to the sealing apparatus.

In one aspect of the invention, the slots are J-shaped and are oriented in such a way that when placed adjacent to one or more connectors, when the actuator is rotated and/or lifted the connectors slide into the slots.

In one aspect of the invention the method further comprises disengaging the sealing apparatus by lowering and uncoupling the actuator from the sealing assembly. The production string rod can push down on the actuator and the actuator interaction assembly, thereby pulling the inner mandrel out of the outer sleeve and contracting the sealing element to disengage the wellbore sealing apparatus. The actuator can be removed from the actuator interaction assembly by positioning and rotating the actuator so that the connectors slide out of the slots.

Since the sealing apparatus is positioned along the production string tubing and the actuator is positioned along the production rod string, there is no need to use a work string or to remove the production string from the wellbore when is it desirable to seal the well to perform maintenance tasks. It also means that it may be possible to provide multiple stimulations per day. In addition, the use of a seating element means that less volume of fluid may be required to perform any necessary treatment and may also improve the degree of success of the treatment.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a partial cross-section side view depicting one embodiment of a production string activated wellbore sealing apparatus.

FIG. 2 is a partial cross-section side view depicting an embodiment of a top connector of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 3 is a cross-section side view depicting an embodiment of an outer sleeve of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 4 is a partial cross-section side view depicting an embodiment of a spring pusher of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 5 is a partial cross-section side view depicting components of an embodiment of a seal piston of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 6 is a partial cross-section side view depicting an embodiment of an inner mandrel of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 7 is a side view depicting an embodiment of a top seal pusher of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 8A is a side view depicting an embodiment of a bottom seal pusher of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 8B is a top view depicting the bottom seal pusher of FIG. 8A.

FIG. 9A is a side view depicting an embodiment of a peg of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 9B is a top view depicting the peg of FIG. 9A.

FIG. 10 is a cross-section side view depicting an embodiment of a top assembly sleeve of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 11A is a top elevation view depicting an embodiment of the assembly body of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 11B is a side elevation view depicting the assembly body of FIG. 11A.

FIG. 12 is a cross-section side view depicting an embodiment of a bottom assembly sleeve of the production string activated wellbore sealing apparatus of FIG. 1.

FIG. 13A is a partial cross-section side view depicting the production string activated wellbore sealing apparatus of FIG. 1 disengaged within a well along with an actuator attached to the end of a production rod string.

FIG. 13B is a partial cross-section side view depicting the production string activated wellbore sealing apparatus of FIG. 1 engaged within a well along using an actuator attached to the end of a production rod string.

FIG. 14A is a side view depicting an embodiment of the actuator of FIGS. 13A and 13B.

FIG. 14B is a top view depicting the actuator of FIG. 14A.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

A production string is comprised of two main components, the production string tubing and the production rod string. The bottom end of the production string is open to allow for fluid to enter into the inner portion of the tubing. The fluid is pulled into the tubing and pushed upwardly by a pump located at the bottom end of the production string. The pump is comprised of a rotor and stator. The rotor is attached to the end of the production rod string, which travels the inner length of the tubing. When it is desirable to deposit fluid into the formation, the production rod string is pulled upward and the rotor is disengaged from the stator so that the fluid can move past the rotor and out the openings at the bottom end of the production string.

The production string activated wellbore sealing apparatus is positioned along the production string tubing, and the actuator is positioned along the production rod string.

Referring to FIG. 1, a preferred embodiment of a production string activated wellbore sealing apparatus is shown. In this embodiment the production string activated wellbore sealing apparatus 10 comprises top connector 20, outer sleeve 30, spring pusher 40, seal piston 100, inner mandrel 90, spring 50, top seal pusher 60, sealing element 70, bottom seal pusher 80 and actuator interaction assembly 140.

Referring to FIG. 2, an embodiment of top connector 20 is shown. The top connector 20 can comprise main body 21, threaded production string tubing insert 27, collar 22, threaded outer sleeve insert 23, central conduit 25 and widened opening 26.

Referring to FIG. 3, an embodiment of outer sleeve 30 is shown. The outer sleeve 30 can comprise main body 31, peg slot 32, first inner threaded opening 36, second inner threaded opening 37 and central conduit 35.

Referring to FIG. 4, in some embodiments, a spring pusher 40 can be used. The spring pusher 40 can comprise main body 41, spring slot 42, threaded outer sleeve insert 43 and mandrel passage 45.

Referring to FIG. 5, an embodiment of the seal piston 100 is shown. The seal piston 100 comprises cap 101 and piston 110. Cap 101 can comprise inner threaded midsection 102, widened opening 103, central conduit 105, seal holder opening 106, seal end 107 and chamfered end 108. Piston 110 can comprise threaded cap insert 111, seal holder 112, first collar 113, central conduit 115, midsection 116, second collar 117, threaded mandrel insert 118 and seal 120. The seal 120 fits over the top of piston 110 at seal holder 112. The inner threaded midsection 102 of cap 101 screws onto the threaded cap insert 111 of piston 110 so that seal holder opening 106 of cap 101 fits around the seal holder 112 of piston 110 and the threaded insert 111 of piston 110 contacts the edge of the central conduit 105 of cap 101 such that the seal 120 can be held in place between the first collar 113 of piston 110 and the seal end 107 of cap 101. The central conduit 115 of piston 110 and the central conduit 105 of cap 101 form one continuous passageway through the center of the seal piston 100.

Referring to FIG. 6, an embodiment of inner mandrel 90 is shown. The inner mandrel 90 comprises main body 91, threaded peg passage 92, collar 93, central conduit 95, threaded channel assembly insert 96 and inner threaded opening 97.

Referring to FIG. 7, an embodiment of top seal pusher 60 is shown. The top seal pusher 60 can comprise seal end 61, chamfered end 62, spring slot 63 and mandrel passage 65.

Referring to FIGS. 8A and 8B, an embodiment of bottom seal pusher 80 is shown. The bottom seal pusher 80 can comprise seal end 81, chamfered end 82 and mandrel passage 85.

Referring to FIGS. 9A and 9B, an embodiment of peg 130 is shown. The peg 130 can comprise threaded section 131, head 132 and wrench slot 133.

Referring to FIGS. 1, 10, 11A, 11B and 12, an embodiment of the actuator interaction assembly 140 is shown. The actuator interaction assembly comprises a top assembly sleeve 150, an assembly body 158, having a first section 160 and a second section 170, and a bottom assembly sleeve 180. The top assembly sleeve 150 can comprise inner mandrel end 151, widened opening 152, inner threaded opening 153, assembly body enclosure 155 and chamfered end 156. The first section of the assembly body 160 can comprise a first slot 161 having slot opening 162, angled portion 163, vertical portion 164 and slot end 165. The second section of the assembly body 170 can comprise s second slot 171 having slot opening 172, angled portion 173, vertical portion 174 and slot end 175. The bottom assembly sleeve 180 can comprise chamfered end 181, enclosure section 182, threaded end 183 and assembly body enclosure 185.

The curvature of the assembly body 158 corresponds to the curvature of the inside of assembly body enclosures 155 and 185 of top assembly sleeve 150 and bottom assembly sleeve 180. Chamfered end 156 of top assembly sleeve 150 can be welded to chamfered end 181 of bottom assembly sleeve 180. The assembly body 158 can be welded to the walls of the cavity formed by assembly body enclosures 155 and 185, and oriented such that the vertical portion 164 and the slot end 165 of the first slot 161 are aligned directly with the vertical portion 174 and the slot end 175 of the second slot 171. The angled portion 163 and the slot opening 162 of first section of the assembly body 160 are oriented in a substantially opposite direction to the angled portion 173 and the slot opening 172 of second section of the assembly body 170. The two gaps between the first and second sections of the assembly body 160 and 170 are oriented opposite one another at the midpoint between the vertical portions 164 and 174 and slot ends 165 and 175. The central conduit 145 of the actuator interaction assembly 140 is formed by the space in the center of the top assembly sleeve 150 and bottom assembly sleeve 180, terminating with bottom opening 190.

The production string activated wellbore sealing apparatus is positioned within the length of a production string tubing, with the top connector 20 being attached to the production string tubing uphole of the apparatus and the bottom opening 190 being attached to the production string tubing downhole of the apparatus. The apparatus is hollow such that it has a passageway along its entire length that allows fluid communication between the uphole and downhole sections of production string tubing.

Referring to FIGS. 1 through 4, the threaded outer sleeve insert 23 of top connector 23 can screw into first inner threaded opening 36 of outer sleeve 30 such that collar 22 of top connector 20 rests against the edge of main body 31 of outer sleeve 30.

When a spring 50 is present, the threaded outer sleeve insert 43 of spring pusher 40 screws into the second inner threaded opening 37 of outer sleeve 30 and the main body 41 of spring pusher 40 can rest against the main body 31 of the outer sleeve 30. The central conduit 25 of top collar 20 and central conduit 35 of outer sleeve 30 therefore form a continuous passageway. Although a spring 50 is shown in the figures, other biasing means may be placed between the sealing element 70 and the outer sleeve 30. An apparatus without a spring or other biasing means is also contemplated.

Referring to FIGS. 1, 5 and 6, to form a continuous passageway, the threaded mandrel insert 118 of seal piston 100 can screw into the inner threaded opening 97 of the inner mandrel 90 such that the second collar 117 of seal piston 110 can rest against the main body 91 of inner mandrel 90 and central conduit 115 of piston 110.

Referring to FIGS. 1 and 4 through 7, the seal piston 100 and main body 91 of inner mandrel 90 can be inserted into outer sleeve 30 and spring pusher 40 through mandrel passage 45 of spring pusher 40. The outer diameter of the main body 91 of the inner mandrel 90 and the inner diameters of mandrel passage 45 of the spring pusher 40 and the main body 31 of outer sleeve 30 can be such that the main body 91 of inner mandrel 90 is telescopically received by the mandrel passage 45 of spring pusher 40 and main body 31 of outer sleeve 30. Seal 120 of seal piston 100 fits snugly against the inside of main body 31 of outer sleeve 30 so that a continuous passageway is formed by central conduit 95 of inner mandrel 90, central conduit 115 of piston 110 of seal piston 100, central conduit 105 of cap 101 of seal piston 100, central conduit 35 of outer sleeve 30. In addition, the central conduit 25 of top collar 20 is isolated from the narrow annulus formed between the outside of main body 91 of the inner mandrel 90 and the inside of main body 31 of the outer sleeve 30. The position and dimensions of the seal piston 100 are such that any fluid or material that may be traveling through the hollow center of the apparatus 10 is not able to escape through the peg slot 32 of the outer sleeve 30 and enter into the space between the outer sleeve 32 and the well casing 2.

It is desirable to keep the production string tubing, actuator interaction assembly 140 and inner mandrel 90 from rotating within the well casing 2. The preferred method to minimize rotation is shown in FIGS. 1, 3, 4, 6, 9A and 9B. The threaded peg passage 92 of the inner mandrel 90 aligns with peg slot 32 of outer sleeve 30 so that outer threaded section 131 of peg 130 can screw into the threaded peg passage 92 of inner mandrel 90. The outer diameter of the head 132 of peg 130 corresponds with the width of the peg slot 32 of the outer sleeve 30 such that there is minimal rotation by the inner mandrel 90 with respect to the outer sleeve 30, while allowing the head 132 of peg 130 can slide back and forth within peg slot 32 of the outer sleeve 30 as the main body 91 of the inner mandrel 90 is retracted into and extended out of the mandrel passage 45 of spring pusher 40. The length of the peg slot 32 and its location on outer sleeve 30 as well as the location of the threaded peg passage 92 of the inner mandrel 90 can be such that the seal 120 of seal piston 100 will always remain completely above the peg slot 32 so that debris cannot enter the central conduit 35 of outer sleeve 30 through peg slot 32. Limiting the rotation of the inner mandrel 90 also limits the rotation of the actuator interaction assembly 140 and the downhole production string tubing. While the figures show the use of a circular peg and an elongated peg slot, it is contemplated that the peg and peg slot may have an alternate shape, for example square or tapered, and an L-shape or a T-shape, respectively.

Referring to FIGS. 1, 4 and 6 through 8B, the bottom seal pusher 80, sealing element 70 and top seal pusher 60 are disposed on the main body 91 of inner mandrel 90. The inner diameters of the mandrel passage 85 of bottom seal pusher 80, sealing element 70 and mandrel passage 65 of top seal pusher 60 may all correspond to the outer diameter of main body 91 of inner mandrel 90. The top seal pusher 60 is positioned uphole of the sealing element 70 and downhole of the outer sleeve 30, while the bottom seal pusher 80 is positioned downhole of the sealing element 70 and uphole of the actuator interaction assembly 140. When in the sealing or engaged position, described below, the top seal pusher 60 produces a downward force on the sealing element 70 and the bottom seal pusher 80 produces an upwards force on the sealing element 70, thereby causing the sealing element 70 to be compressed. The top seal pusher may be contiguous with the outer sleeve 30, the sealing element 70, both or neither when the sealing apparatus is in the disengaged position. Similarly, the bottom seal pusher may be contiguous with the actuator interaction assembly 140, the sealing element 70, both or neither when the sealing apparatus is in the disengaged position.

In the preferred embodiment, chamfered end 82 of the bottom seal pusher 80 rests against collar 93 of the inner mandrel 90. The sealing element 70 is positioned between seal end 81 of bottom seal pusher 80 and seal end 61 of top seal pusher 60.

When present, the spring 50 is disposed on the main body 91 of the inner mandrel 90 and may have an inner diameter that corresponds to the outer diameter of the main body 91 of the inner mandrel 90. The bottom of the spring 50 can rest in the spring slot 63 of the top seal pusher 60 and top of spring 50 can rest in spring slot 42 of spring pusher 40.

Referring to FIGS. 1, 6 and 10, the threaded assembly insert 96 of inner mandrel 90 can screw into the inner threaded opening 153 of the top assembly sleeve 150 of actuator interaction assembly 140 such that collar 93 of inner mandrel 90 can rest within widened opening 152 of top assembly sleeve 150.

The wellbore sealing apparatus 10 interacts with an actuator 200. The actuator 200 is positioned along the production rod string, which runs longitudinally through the internal passageway of the production string tubing.

In one embodiment, as shown in FIGS. 14A and 14B, the actuator 200 has connectors 202 which interact with the slots in the assembly body 158. Alternatively, the slots can be located in the actuator 200 and the connectors can be located in the assembly body 158.

In use, the wellbore sealing apparatus 10 is placed at a certain point along the production string and lowered into the well 1. Similarly, the actuator 200 is placed at a certain point along the production rod string 3 and lowered into the well 1. The sealing apparatus is engaged or disengaged using actuator 200, through the movement of the production rod string 3.

When the well is producing oil the sealing apparatus 10 is in its disengaged state, meaning the sealing element 70 is relaxed and not contacting the well casing 2. To move the apparatus into its sealed or engaged position, the production rod string 3 is pulled upwardly so that the actuator 200 couples to the actuator interaction assembly. This coupling results in the upward movement of the inner mandrel 90 telescopically into the outer sleeve 30, thereby causing the top seal pusher 60 and bottom seal pusher 80 to exert opposing forces on the sealing element 70. This pressure results in the sealing element 70 compressing vertically and extending horizontally thereby creating a seal with the well casing 2.

In the preferred embodiment the coupling of the actuator 200 and the actuator interaction assembly 140 occurs as a result of the alignment of the slots and connectors on the assembly body 158 and actuator 200, respectively. In an alternate embodiment, the slots may be found on the actuator 200 and the connectors on the assembly body 158. While the figures show the preferred use of round connectors and J-shaped slots, it is contemplated that other shapes of connectors and slots can be used to couple the actuator 200 and the actuator interaction assembly 140.

In order to engage the apparatus of the preferred embodiment, the connectors 202 on the actuator 200 should first align vertically with the first and second slot openings 162 and 172 of the assembly body 158. Next, the production rod string 3 is rotated such that connectors 202 enter slots 161 and 171. The production rod string continues to be rotated and raised until connectors 202 contact slot ends 165 and 175. Once this coupling has occurred, the production rod string 3 can pull up on actuator 200 and thus actuator interaction assembly 140, causing the top and bottom seal pushers to move towards each other and exert opposing forces on the sealing element 7. These opposing forces compress the sealing element vertically, while expanding it horizontally. When a spring 50, or other biasing means, is present, it can assist in the compressing of the sealing element 70 by placing additional force on the top or bottom seal pushers or both. At the same time, the inner mandrel 90 and seal piston 100 to slide up into the outer sleeve 30.

The apparatus is fully engaged when sealing element 70 forms an airtight seal against well casing 2 of well 1, isolating the upper well section 4 from the lower well section 5.

With the lower section of the well being sealed off from the upper section of the well, fluid or other material may be injected into the well.

After the maintenance is completed, the sealing apparatus can be disengaged using the production rod string 3. The actuator 200 is lowered and allows the force of gravity to act on the actuator interaction assembly 140 and inner mandrel 90. The pressure on the sealing element 70 from the top and bottom seal pushers is relaxed, which allows sealing element 70 to expand vertically and retract horizontally, removing the seal between sealing element 70 and well casing 2 of well 1. When present, the force of the spring 50, or other biasing means, can also assist in sliding the inner mandrel 90 and seal piston 100 out of outer sleeve 30.

Once the sealing apparatus is disengaged the well can quickly begin producing again. If the maintenance process did not adequately fix the production problem, the sealing apparatus can be re-engaged and subsequent maintenance can begin. Therefore, multiple stimulation of the well may occur in one day.

In the preferred embodiment, the production rod string 3 can raise and lower the actuator 200 past the actuator interaction assembly 140 by rotating the actuator 200 so that connectors 200 are oriented to pass through the gaps between first assembly body 160 and second assembly body 170. This allows the rotor and/or actuator 200 to be removed and serviced without have to remove the production string tubing. Alternatively, where the connectors are on the assembly body, the gaps are located in the actuator.

In some embodiments there is a widened opening 26 of top connector 20 to prevent attachments on the end of production rod string 3 from getting caught on the threaded outer sleeve insert 23 of the top connector 20 as the production rod string 3 is being raised. Similarly, the widened opening 103 of cap 101 of seal piston 100 can prevent attachments on the end of production rod string 3 from getting caught on the cap 101 of seal piston 100 as production rod string 3 is being lowered.

Although a few embodiments have been shown and described, it wilt be appreciated by those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof, it being recognized that the invention is defined and limited only by the claims that follow. 

We claim:
 1. A wellbore sealing apparatus positioned along production string tubing, the apparatus comprising, an outer sleeve, having an uphole end, a downhole end and a slot positioned between both ends; an inner mandrel telescopically received within the downhole end of the outer sleeve, a downhole end and a midsection, the midsection having a peg positioned to interact with the slot in the outer sleeve; a compressible and horizontally expanding sealing element disposed on the midsection of the inner mandrel; an actuator interaction assembly, disposed on the downhole end of the inner mandrel, having a means to couple to an actuator; a top seal pusher disposed on the inner mandrel positioned between the outer sleeve and the sealing element; and a bottom seal pusher disposed on the inner mandrel positioned between the sealing element and the actuator interaction assembly; wherein when the actuator interaction assembly couples to the actuator, the inner mandrel is pushed into the outer sleeve and the top and bottom seal pushers exert pressure on the sealing element such that it compresses and expands to form a seal with the wellbore.
 2. The apparatus of claim 1, wherein the actuator interaction assembly comprises an assembly body having at least one slot.
 3. The apparatus of claim 2, wherein the at least one slot is J-shaped.
 4. The apparatus of claim 1, wherein the actuator interaction assembly comprises an assembly body having a least one connector.
 5. The apparatus of claim 1, wherein the actuator interaction assembly further comprises a top assembly sleeve and a bottom assembly sleeve.
 6. The apparatus of claim 1, further comprising a seal piston disposed on the uphole end of the inner mandrel.
 7. The apparatus of claim 1, wherein the actuator interaction assembly comprises an assembly body having a first section and a second section with at least one gap between the first and section sections.
 8. The apparatus of claim 1, further comprising a biasing means disposed on the inner mandrel between the top pusher and the outer sleeve.
 9. An actuator positioned along a production rod string, for interacting with a sealing apparatus, the actuator comprising a coupling means wherein when the production rod string is pulled upwardly the actuator couples to the sealing apparatus.
 10. The actuator of claim 9, wherein the coupling means is at least one connector.
 11. The actuator of claim 9, wherein the coupling means is at least one slot.
 12. The actuator of claim 11, wherein the at least one slot is J-shaped.
 13. The actuator of claim 9, further comprising at least one by-pass gap extending longitudinally along the length of the actuator.
 14. A method of sealing a wellbore using a production string, the method comprising, providing a sealing apparatus having a sealing element and an actuator interaction assembly positioned along a production string tubing; providing an actuator positioned along a production rod string; coupling the actuator with the actuator interaction assembly; compressing and expanding the sealing element of the sealing apparatus; and forming a seal between the sealing apparatus and the wellbore casing.
 15. The method of claim 14, further comprising disengaging the sealing apparatus from the wellbore by lowering the actuator and uncoupling the actuator from the actuator interaction assembly. 